PFR Review and Outlook Roundtable February 2021
To download a PDF version of this report, click here.
From the discovery of a troubling, deadly new disease in the Chinese province of Hubei in January, to the dawning realization that the virus had already spread silently around the world, the implementation of lockdown measures and a race to develop vaccines, the Covid-19 pandemic dominated life in 2020, including for power and renewable energy financiers.
Offices were vacated and development and project finance teams were forced to coordinate virtually. If you were not an expert at video conferencing going into the pandemic, you will have had ample opportunity to boost your skills by the end of it.
Meanwhile, Donald Trump and Joe Biden were engaged in a presidential election campaign that had to be conducted largely remotely, but that was no less bitterly fought for that. The campaign gave way in November to a tense, protracted vote count and claims of fraud. Biden was eventually declared the winner on November 7, four days after election day.
Throughout this turbulent year, developers, project finance bankers and investors of various kinds had to grapple with volatile markets, especially in March and April, when the seriousness of the pandemic became clear, sending markets into freefall. Beyond the financial markets, officials had to confront the possibility of delayed deliveries of equipment, claims of force majeure and stretched construction schedules.
However, project finance lenders and investors tend to take a long-term view of things, and place a good deal of importance on strong relationships. The wind farms and solar projects that were in the market for financing would still be needed after the pandemic, and their sponsors would be back with more business in the future. So bank loan and tax equity deals went ahead on previously circled terms, even as bond yields and stock prices yo-yoed around them.
And so, as we go forward into 2021, and hopefully emerge from the Covid-19 crisis, the great North American project finance engine seems to be in much the same shape as it was before.
Change is coming, of course, but it is not driven primarily by pandemics or politics.
It is being driven by new technologies such as battery energy storage and carbon capture, new business models such as distributed and community energy, and new risk management products such as shaped power purchase agreements and proxy revenue swaps.
We hope you will be, too.
Bob Cantey, Managing Director, Head of Infrastructure Debt, Nuveen
Steve Petricone, Managing Director, Co-Head of Energy and Infrastructure, Fortress Investment Group
Jonathan Cheng, Director, Renewable Energy, RBC Capital Markets
Meghan Schultz, Senior Vice President, Finance & Capital Markets, Invenergy
Richard Metcalf, Editor, Power Finance & Risk (Moderator)
PFR: With the Covid-19 pandemic, everyone has had to transition to different ways of working, in particular remote working. How has market infrastructure adapted to remote working, and do you think any of the changes will be permanent?
Brian Goldstein, CoBank: Overall, you'd be surprised at the ability of the bank to continue to transact business in spite of working remotely. We have roughly 20 people on the team and so coordinating all of that underwriting activity, portfolio management activity, compliance work is pretty collaborative. Our ability to successfully manage that for the past year has been outstanding. We actually had our best year ever in the project finance group. We underwrote more transactions and executed more opportunities than we ever had.
We benefited in part in that we were well-capitalized and so when the pandemic first rolled out and the market backed away in March and April, CoBank was able to continue to actively engage in the market. That gave us a really strong second quarter. And then we've been able, as the markets recovered in the second half of the year, to continue to successfully obtain engagements and underwritings and continue to close the year in a very strong way.
As we look back, we are anxious to get back to working together in a single location. We need to continue to work in teams. It's important, to be effectively collaborative, to be together. But the fact that we were as successful as we were suggests that how we work going forward is going to be a lot more flexible than it has historically.
Steve Petricone, Fortress: We have also had a relatively smooth experience with respect to remote working, but it obviously takes a lot of effort to make sure you don’t lose the benefits of interpersonal collaboration in a post Covid world.
That's especially the case for junior staff who require some mentoring, but I would also say it's harder to develop and execute innovate ideas when everyone's at home, even with Zoom or WebEx or whatever.
For us, culturally, pre-pandemic, the way that our team was set up, having an open trading floor, allowed for a lot of continual face to face interaction, and that level of information flow and the ability to move quickly was a big part of our success. So, each team member basically knew, just from that informal interaction, what everyone was working on, which isn't always the case now, so you have tohave a specific strategy for that interaction to continue.
PFR: Meghan, from a borrower's point of view, we have heard that transacting with parties that you already have a good relationship with has been relatively easy and has continued quite smoothly, but that developing relationships with new investors or lenders that you don’t have so much of an existing relationship with has been a little bit more difficult. What's your perspective on that?
Meghan Schultz, Invenergy: I don't know that I would completely agree with that from Invenergy's perspective. We also had a record year with the capital that we raised and the number of projects that we either started or completed construction on.
We actually closed a deal with CoBank as one of the lenders on March 27. That was an incredibly stressful time, truly right in the middle of when the pandemic was really hitting and people were trying to understand what that meant.
We were able to maintain the terms that we had agreed to pre-pandemic. That showed to us the strength of the relationship, the ability to execute despite the challenges and really not skip a beat. We were scheduled to close by the end of March, which we did, and that really was the case for us throughout the year. We did many transactions with repeat lenders and investors.
We also raised capital from a number of new sources. We added at least four or five lenders to the mix this year, as well as tax equity investors that we hadn't done investments with before. So we were able to extend relationships and continue to execute, although of course there were things we had to work through along the way.
One thing – which is a seemingly minor thing but so critical – is that banks finally agreed to accept electronic signatures, which was amazing. That happened really fast, so hopefully we don't have to go back to originals.
PFR: That's a really interesting detail. Is that the case with all facilities? Does that apply to letters of credit as well?
Schultz, Invenergy: There are a few things, like where the bank has to issue an original letter of credit to the beneficiary, but just about everything else… One or two banks out of the probably 20 that we worked with this year were still looking for original signatures. But it's definitely now the exception rather than the rule.
PFR: Does that translate across to tax equity as well, Jonathan?
Jonathan Cheng, RBC Capital Markets: Yes, I would echo the other responses in terms of the transition of our business as pretty seamless during the pandemic. I joined RBC at the beginning of the shutdown, so I don't have a frame of reference for working in the office at RBC and I personally am interested in returning to the office and having that collaboration in person.
Similarly, we had a record year this past year after a brief pause by investors. They re-engaged pretty quickly. We doubled our previous year's investment amount and really had a seamless transition to the new working structure.
We're all looking forward to collaborating in person in the near future. Having this proven working structure and having the additional flexibility to collaborate amongst our team, our investors and our sponsor-partners just adds another tool for us in the future.
PFR: Bob, anything to add on market infrastructure regarding the private placement market?
Bob Cantey, Nuveen: It sounds very similar to everybody else – a record year. The second quarter was the strongest quarter we have had since I have been in the group. A lot of people were out of the market and we decided to stay in and that allowed us to receive strong allocations and value. By June we had completed 70% of our program.
I think we've adjusted pretty well to it. We need to get back to the office, especially in regards to junior staff development. But we're going to have a lot more flexibility going forward.
PFR: Another big theme that has continued to play a more and more important role is sustainability, or using ESG criteria when making investment decisions. Obviously for renewable energy tax equity, it's slightly more baked into the product because it is what it is. But how does this trend affect market dynamics?
Goldstein, CoBank: We are impacted by it more indirectly. CoBank is a private enterprise. We're a co-op, owned by our members. So, we don't have public market pressure. The influence generally comes from our shareholders, who are also our customers. And given the nature of that customer base, many of whom are generation and transmission co-ops, they own a broad range of technologies on the power production side. While we are mindful of our strategy towards renewables, and clearly our business focus in project finance is primarily towards the renewables space, we're not seeing as much internal pressure to focus primarily on renewables.
That said, we are very mindful of how it affects the overall market, to the extent that we're looking at refinancing certain assets, particularly coal assets. While we may not have a prohibition on looking at those transactions, we also need to recognize that the supply of capital interested in financing those assets is going to be limited. We're factoring that in to the decisions we make with respect to which deals we want to pursue.
PFR: Is this dynamic affecting pricing, or the cost of capital, if certain segments of the market are more crowded than others?
Schultz, Invenergy: One of the impacts that we see is just an increase in liquidity available to renewable projects and renewable developers across the capital stack, whether you're looking at development capital, traditional cash equity or on the debt side. The competition for deals is driving down the cost of capital.
So then, from a sponsor perspective, you have lower cost of capital but so do many other parties out in the market, and so there has been a lot of competition as far as securing offtake agreements etc. is concerned, which results in lower costs of energy being delivered to customers as well.
One area where that doesn't apply in the capital stack is tax equity, because there is such a shortage of tax equity. That gives those investors outsize leverage to dictate pricing and terms.
PFR: Is there also a risk of having stranded assets as states transition away from carbon emitting generation resources? How are lenders looking at that risk and what, if anything, can be done to mitigate it?
Cantey, Nuveen: That is something that we're focusing on this year. We're not allowed to do anything coal-related anymore and we have been asked to focus on fossil fuel stranded-asset risk. The concern is, you're seeing certain states and the current federal administration talking about phasing out other types of fossil fuels, such as gas. I'm not saying whether it can actually happen or not, but the mere fact they're talking about it gives us pause. We want to make sure that we limit our merchant risk for longer-tail assets, because we don't want to be in a situation where our investments are forced into retirement early. We're sticking more with PPAs and we're moving away from natural gas plants that might have merchant tail risk in certain areas of the country because of the stranded asset issue. Going forward if I want to participate in a fossil fuel-related business, I have to justify internally why I don't think there is stranded asset risk.
PFR: Steve, this is especially relevant for the term loan B market, given that there are some single-asset coal-fired plants and a lot of gas-fired generation in that market.
Petricone, Fortress: Yes. There are two sides to the coin of stranded asset risk. On the one hand, there's a new challenge in the term loan B market, with longer-term existential risk for some of these credits, and in general, probably other risks that have not been priced in. And these are, in the power space, uncertainty and volatility around the energy and capacity markets where, as was implied in the last comment, existing deals are no longer really expected to amortize over the seven year maturity.
So, as a lender you have to say, ‘Okay, am I going to get eventually to a safe place, from a collateral or from a loan-to-value standpoint?’ Ultimately this means less leverage going forward, or perhaps pricing that reflects some amount of equity-like risk.
One existential risk is the timing and the depth of demand destruction for many assets across not just power but midstream and downstream.
A second risk would be energy transition competition. A market we’re very familiar with is gas-fired power assets in Ercot. These assets now have wind and solar to deal with. They're challenging the most efficient CCGTs that earn almost all their Ebitda in the summer months through scarcity pricing. It also may dramatically impact ISO-New England, for example, with all the cheap hydro that could enter the market through new transmission. When investing in these markets, we think about which assets will be survivors and the beneficiaries of offsetting retirements of less efficient fossil assets through the energy transition.
A third is policy risk, which used to be limited to markets like California, but it's now in PJM and even New York-ISO.
The upside to that, though, as an opportunistic lender, which we are, is that because of those risks, and also because of a philosophical flight to ESG, there may be a perception of credit risk and volatility around traditional energy that is disproportionate to the actual risk, and that also creates an opportunity. You've already seen it happen in the upstream space, where certain banks, particularly European and Canadian banks, are getting out of North American upstream energy. And, by the way, you naturally have the opposite happening in ESG-related lending, a space which appears to be getting more crowded.
One question is, when will this ultimately impact the capital supply for other fossil fuel-related energy infrastructure assets more broadly, including pipelines and product storage and refineries and terminals? Is it just a matter of time? This is probably less of an issue for term loan Bs than for term loan As, but there could soon be a period where there's just significantly less capital available for non-ESG assets, and that could be an opportunity for term loan B lenders, who want to be involved in that market, to finally see some yield.
PFR: Very interesting. Focusing now on the term loan A market, Brian, could you give a quick overview of the kinds of participants in US power and renewable energy project finance, the range of risk/reward appetites that you see and where CoBank fits in?
The market is really bifurcated between those that are primarily focused on long-term contracted assets and a second group that is really the part that Steve was referring to, where the term loan A is a non-fully amortizing transaction with merchant risk, generally on a thermal asset. These deals will include a number of lenders who like the higher yield and overall risk-return profiles. They tend to have mini-perm structures either for greenfield development of gas-fired assets or the refinancing of those assets.
The majority of the volume that we have seen at CoBank has really been in the renewables space. But it has evolved over time. Two or three years ago, there was a lot of activity financing plants in PJM, that kind of moved as those plants were built, the supply-demand balance changed, lenders started looking at other markets such as New England and New York.
What we're seeing today, on the renewables side, is a lot of lenders trying to find ways to respond to the sponsor's need to continue to drive down the cost of capital and extend out the amortization profile. As their need to win these RFPs causes sponsors to bid lower PPA prices, one way that they can get a return on that project is by reducing the cost of capital and extending out the recovery of that capital.
A number of lenders have differentiated themselves in the renewables space by taking merchant tail risk beyond the PPA period. There is a smaller number of lenders, at this point, that are comfortable doing that. They also tend to be lenders that are much more active in selling loans into the market to retail investors. Our sense is that because they're able to manage their overall exposure by selling down sizeable portions of that loan more broadly into the market, they're more comfortable continuing to do those types of transactions. CoBank does less of that, and so our appetite for those merchant tails is, as a result, constrained, because we tend to hold our loans to maturity and don't sell them as much.
PFR: Last year, like every market, it was affected by the outbreak of the pandemic and the impact of that on the broader economy. Has the bank loan market recovered fully now since March and April last year to the point where liquidity and pricing are where they were before the pandemic started or even possibly tighter?
Goldstein, CoBank: Definitely, the market has fully recovered to pre-pandemic levels of pricing, and in some cases we're seeing additional competitive pressures pushing stuctures and pricing in some cases even below those levels.
PFR: It looks like 2021 is going to be another big year for renewable energy project finance loans. Do you see any opportunities in the gas-fired power sector?
Goldstein, CoBank: We do, but, again, given our overall appetite for merchant risk, we've been relatively selective. Last year we participated in three financings for gas-fired assets in Texas. They were particularly well-located. We saw some very attractive hedge structures put in place to materially amortize down the loan. With the remaining residual exposure we had, particularly given the locational value that we attributed to those assets, we were comfortable with that. But again, with our modest appetite we will be selective.
I think 2021 is going to be very similar to 2020. There will be more renewables. There will be a lot more batteries financed. I also expect that the deal volume overall will be in line with or potentially even greater than 2020.
It was not something we expected as we were going into our fourth quarter budgeting process, but clearly, with the tax extenders that were approved in December, it gave a lot longer runway for new development than we had initially anticipated. That will go a long way to continue to encourage the volume of activity in 2021 to be in line with 2020 and maybe even greater.
PFR: In terms of pricing, you said that the market had fully recovered. We have heard of construction-only loans being priced inside 100 basis points over Libor, and back-leveraged, mini-perm loans perhaps slightly wider of that, 125 bp for a contracted renewable energy project. Can you say anything more about pricing?
Goldstein, CoBank: The ranges you're talking about are very much what we're seeing. If it's a build-own-transfer of less than 12 months, the margin may be lower. But there are fees, and so when you look at your all-in 12-month return, it still hurdles. If those maturities are beyond a year, you start looking at the pricing that you referred to in a more traditional construction-converting-to-a-term loan.
I suspect we'll continue to see some pressure on that. The question is, will the cost of funding for the lenders and the cost of capital move in a direction that will cause this pricing to be a floor, or will we continue to see ongoing pressure?
Part of that is supply and demand. We're seeing a lot of lenders coming into the space and not as many transactions. Hopefully if we have more volume of financing activity, that will help pull us back into balance and hold pricing where it is.
PFR: Does this competitive dynamic also translate into pressure on the premiums that banks might look for in exchange for additional risk in the form of merchant tails or structural subordination?
Goldstein, CoBank: We have not seen that much pricing differential from projects that do not have merchant tails from those that do. We suspect that because those transactions are structured primarily as mini-perms, there's an expectation on the part of the lenders in their analysis that when that mini-perm is set to be refinanced, people have more visibility on the merchant tail. To the extent that that tail looks riskier, then the pricing will start to reflect that. To the extent that merchant tail looks comfortable, then we would expect to see less impact on the refinancing price.
PFR: Thanks very much, Brian. I'd like to move on to the project bond or private placement market next, Bob. Again, if you could just begin by giving an overview of the market and the participants in that market.
Cantey, Nuveen: The majority of our market is investment grade. There is some high yield. Brian, when you were talking about your loans, are they generally triple-B minus metrics or are you down in the double-B space?
Goldstein, CoBank: These are almost all low investment grade, with strong investment grade offtakes and conventional debt sizing metrics.
In regards to risk, we do take merchant tail risk for renewables. However, we go through a rigorous underwriting process. We have to make sure that the power prices or capacity prices that we're seeing today can make money during the merchant tail.
The first couple of deals we did like that, it was just us and a few other shops. The market is changing and more and more shops are feeling comfortable with merchant tail risk. That's an area of growth we'll see in 2021 – more merchant tail risk in the renewable space.
In the senior debt natural gas space, with merchant tail risk, we shy a bit more away from it, because of the stranded-asset risk. But it seems like that is open, too, in our market. There's a lot of money in the investment grade space and it's pushing people to do things they might not have done a couple of years ago.
PFR: In terms of liquidity and pricing, has that, similarly to the bank market, recovered to pre-pandemic levels?
Cantey, Nuveen: It has. If your definition of liquidity is how many participants are in the market, everybody is back, and there seem to be more participants. Pricing is back to pre-Covid levels. The big difference, of course, is that Treasurys are much lower, so our overall coupon yields are lower, and that can be a bit painful for us. But the market has shaken off the pandemic, in my opinion, at this point, especially in the renewables space. There's lots of demand.
PFR: In terms of spreads, what can people expect to see for a contracted renewable energy project if they do a private placement?
Cantey, Nuveen: Hopefully bankers won’t quote me on this, but if you see a solar or wind project, triple-B minus, with a decent offtake, I've seen 175 bp, 185 bp off the curve. Now, if you add some merchant tail risk, maybe 25 bp or 30 bp more. That really depends on how low merchant prices can fall in the tail years and you still have a debt service coverage of at least 1x.
PFR: The private placement market is primarily a buy-and-hold market. There is a secondary market but it's by appointment only. When you have big disruptive events that may have an impact on credits, that can cause problems for some participants in terms of credit ratings. Was there any of that last year as a result of the pandemic?
Cantey, Nuveen: We definitely had some downgrades. Now, did I see wholesale selling? No. We all use the same secondary shops. You have to remember that in our marketplace, when you get downgraded to double-B, typically there's a modification or waiver that is requested, and based on the structure, we have a seat at the table. So, we're going, as we speak now, through a lot of negotiations with borrowers. You have to let that process play out before you make a decision. We do have security. We do have a seat at the table. A lot of people – myself and peers – get comfort in that and we use that to hopefully structure the deal so that we can either get back to an investment grade rating or maybe change some things and then feel more comfortable holding it as a high yield note.
I do see some people trying to sell, but I've not seen wholesale sales. You'll get a chunk of project bonds sold here and there, but most people, unless you think it's going to go bankrupt, tend to stick with it and make the modifications and waivers and work with the sponsors and see how things evolve. We're doing that in a lot of different places right now.
PFR: In terms of supply into your market, did you feel like that was affected last year? Is there enough supply into your market to meet the demand from the lifecos?
Cantey, Nuveen: There could be more supply and it would be easily met. So, to answer your question, no. There doesn't seem to be enough supply, because I can't get enough supply. If I want $100 million or $150 million of a deal, they’re giving me $40 million. They could easily put more in the market.
The market did shut down for a little bit last year but it quickly started up again in June, and since then it's been humming along.
This year we haven't done a lot of new deals, but typically the first quarter of any year is when people are sounding out the market, trying to decide if they're going to be in the bank market or are they going to be in our market. That's what's happening right now.
I would assume this year is probably going to be probably fairly flat to last year. Last year was a good year, despite the pandemic. There were a lot of people anxious to get deals done because of the low rates and worries about the presidential election.
I'm hopeful that this year will be another good year. But anybody who wants to issue, please, our market is wide open. There's a lot of demand.
PFR: Is there anything in particular you would like to see more of?
Cantey, Nuveen: I would like to see more commercial and industrial solar. That's a big growth space. We've done some of those deals. It's very difficult to structure. We've done some and with tax equity ahead of us in a holdco structure.
I'd like to see some battery storage. Brian mentioned that and people have asked us about that. For us, in the private market, one thing we'll have to overcome is if we have somebody with a PPA, that's great, but how do we figure out, if in year seven or eight the batteries don't work as well as intended, how do we structure for that? An O&M reserve? A capex reserve? I think it can be done, and we're looking to do it. We've had people approach us. I think a lot of them fall off to the bank market, but in our market, we can go a little bit longer sometimes, and I think this will be a future growth area. We're looking to get a deal done there for sure. I'd love to see some of those.
PFR: It would be interesting, with such a new technology, especially if you were trying to put longer-term debt on it, when there isn't so much operational data going out that far.
Cantey, Nuveen: True. That's where the protection would come in, besides the reserve accounts, similar to some wind and solar farms where we have an O&M agreement with, say, a General Electric, or some other entity, where they take some of the risk too. I would envision somebody running the batteries who felt strongly enough about it to say, ‘You have “X” risk, but if something happens past point B, we'll be liable for that.’ That would be a way to structure it, along with reserve accounts.
As the years go by, we'll figure out what works and what doesn't, and whether we still need these mechanisms.
PFR: If life insurance companies and other private placement market participants are looking for more supply, are they also getting more comfortable with non-traditional offtake arrangements such as hedges with a little bit more financial engineering?
Cantey, Nuveen: We have not seen a lot of those. We'd take a look at it, for sure. We've seen some people come with a five- or six-year hedge, but then there is lots of merchant tail risk, and it didn't quite work out. Texas is difficult for us, because of the volatility in prices. We've seen some of that in Texas. But I think that's something that people in the market will take a look at, and we would take a look at definitely.
PFR: You also mentioned C&I solar. That's slightly different from an ordinary utility PPA but it seems like private placement investors are quite happy with that proposition as well.
Cantey, Nuveen: Yes.
PFR: Even though, presumably, a lot of the offtakers in that case are unrated or not investment grade?
Cantey, Nuveen: They tend to put a lot of these credits together, so the overall diversity of the portfolio is the way to approach it. That's how we've looked at it. And then we run analysis on how low the prices can get in certain areas once these contracts roll off.
PFR: Have you looked at any community solar deals or is that a little way off?
Cantey, Nuveen: We have people talking to us about community solar. We did do a C&I deal with a chunk of community solar in it, but that varies so much state by state. That was our first time we'd done that. We'd like to see more of it. To me, personally as a homeowner, I'd rather have community solar than put something on top of my roof and have my neighbors hate me. I would like to see some deals.
PFR: We'll now move onto leveraged loans or term loan Bs. Steve, could you give us an overview of your market as it pertains to power and renewable energy project finance?
We now more often need to ask ourselves, at any given year in our forecast, given the potential volatility around revenue, do we mind owning the asset at that level? Because from time to time we have actually stepped into the ownership shoes, usually with full knowledge beforehand, but not always. I think practically any lender in our space exposed to merchant revenue has to ask that question.
Just to give you an example, in the midstream space, with lower volumes and weakening offtaker credit, you now have to look at the credit – whether you buy in the secondary market, where we are very active, or a new issue, which we haven't seen lately – and ask the question, what happens if the contract is rejected?
Specifically, now, you have to study the differentials and ask, ‘Okay, can I live with that, if I lose one or two of my counterparties, perhaps a major counterparty who may file, and those contracts are renegotiated to market pricing?’ It's a new lens you have to have.
I would say there's an interesting glimmer of hope in midstream from a valuation perspective. Especially under the current administration, and with the cancellation of Keystone and Atlantic Coast, at least for assets outside the Permian, there seems to be increasing scarcity value for some existing assets. That’s supportive from a long-term fundamental need standpoint, both from a secondary debt standpoint and from a refinancing standpoint.
PFR: Give us a general idea of how the pandemic affected outstanding loans, how long the market was closed to new issuance, and what's happened since then. Bring us up to date.
Petricone, Fortress: Well, the pandemic created a really unique opportunity in both providing capital to firms undergoing cash flow or liquidity issues, but also it presented an historic secondary buying environment for term loan Bs in those companies, at least for a few months from, say, March to May. If you recall, as exemplified by below-negative-$30 crude in April, there was really a flight for the exits at that time. If you track the term loan Bs, we were surprised how this March-to-May disruption affected even some of the really higher-quality credits, which created a unique buying opportunity for select names. However, not surprisingly, the issue was always the amount of volume that was actually trading.
There was a general feeling of existing holders trying to run out of the burning theater, but when you look at the tape of what happened to term loan B pricing during that period, it would be interesting, and I haven't seen that data, to compare that to the actual trading volume. It may not have been that high in some issues where the loan pricing collapsed.
Now you're back to pre-pandemic levels for most credits. For some credits, we're really not out of the woods yet from a credit perspective, just because of actual demand destruction and fundamental negative changes in their markets. An example of that would be some of the sponsor-backed pipelines but also some power plants.
Where we've seen current term loan B trading levels, when we've done credit analyses on some of those names that are still trading in the 70s and 80s, as opposed to so many credits that have returned to par, those prices tend to represent the most optimistic valuations for those assets.
Sometimes, both on new assets and on existing assets where we think the trading values could be volatile, we will pre-underwrite those issues and we'll wait until pricing aligns with actual value. And I think that on some of those names, particularly the midstream space, there is room for future opportunistic purchases.
PFR: Do you expect there to be much new issuance in the term loan B market from the power sector this year and if so, where is that going to come from? Acquisitions, refinancing?
Petricone, Fortress: There will certainly be some refinancing. You can see the upcoming maturities. We're tracking those closely. It will be interesting to see what happens, particularly with single-asset refinancing, where market demand seems to have decreased.
We're hoping for more volume in the institutional loan space, in power and midstream. I'm not sure how much we will see yet, but certainly, as I mentioned with upcoming maturities, that's something that we watch closely because some of those could result in restructurings. We have less visibility into new loan issuance associated with potential acquisition financings and dividend recapitalizations, especially with some of the market uncertainties that we’ve been discussing.
PFR: And for a double-B power credit in the term loan B market, can you say where they could expect to get pricing in today's market?
Petricone, Fortress: I haven't seen a lot of new issues. I could do it on the basis of secondary trading levels, but there's a wide range of spreads. Some double-B-rated single-asset deals are trading at well over 4% yield, but very generally, I’d say for a new double-B deal, a 3.5% to 4% spread is normal. A high-quality double-B-flat asset portfolio will have a spread closer to 3% or 3.5%.
PFR: You mentioned restructuring. Is there much that you expect to be restructured this year?
Petricone, Fortress: I do think that there are a handful of single-asset maturities coming up, and it's unclear whether those are going to require restructuring or are going to be refinanced at perhaps higher pricing, or whether there will be an equity injection to assist in that. I guess technically that's a restructuring, but I think it remains to be seen. Additionally, given demand destruction, relatively mild weather last year and post-issuance loan upsizing,s financial covenant trip-driven restructurings are a possibility.
PFR: If you have a single-asset coal-fired plant financed in the term loan B market, I get the sense that it's been more difficult to get those transactions through recently just because it's coal. Is it going to reach a point where it's virtually impossible to do that?
Petricone, Fortress: It's tough for coal because of this double dynamic. One is that you just have fewer lenders who will get involved in that sector as a matter of policy. Brian was talking about that. I know that CoBank can still be engaged in lending in coal-fired power and in fact I believe a borrower of ours has been in discussions with them from time to time. That's a t refinance a coal-fired power plant – contracted, I should add.
So one aspect is the philosophical pullback from that sector, and then the second is that, as merchant assets, many just can't compete economically, due to the challenges of high fixed costs, the need to go from baseload to intermittent generation, and the necessity of pushing down fuel costs. We have spent time looking very closely at some single-asset coal-fired merchant projects in need of refinancing, and we’ve really been challenged by the economic fundamentals.
As more and more renewables come online, combined with still-low commodity prices in natural gas, we're going to continue t see a lot of financial pressure on those assets. Additionally, financial pressure on these assets reduces the appetite to invest in maintenance capex in what are typically older assets.
PFR: On the flip side, are term loan B investors clamoring for more supply from the renewable energy sector? There was a deal last year from ExGen Renewables. Is there going to be more of that?
Petricone, Fortress: Hopefully yes. To your point, we haven't seen significant volume in institutional loans for renewables, just because very often it's not the most efficient way for renewable projects, particularly contracted or even partially merchant, to finance themselves.
Maybe if fewer bank lenders have the appetite to be involved in partially merchant or merchant-tail renewable assets, that will provide more of an opportunity for institutional lenders to participate.
I also think that it is likely – at least anecdotally – that institutional lenders may have less of an ESG mandate. But it would be good to see more ESG or transitional energy loans in the term loan B space, certainly.
PFR: Jonathan, RBC provides tax equity for sectors outside of renewable energy, but specifically with regards to renewable energy, pretty much any renewable energy project that is developed in the US will want to have tax equity involved, so the tax equity market somehow has to cater for all of them. Is there much difference between different tax equity investors in terms of what they can do, structures that they prefer, whether they syndicate to other investors or not, and where does RBC fit into that?
We typically use the partnership flip structure, but we do have flexibility, depending on sponsor partner preference for other structures. It also depends on the investor.
This coming year, given the appetite of our investors, which fortunately was maintained throughout Covid, we’re looking at an uptick in demand. RBC expects to launch a diversified renewable energy tax credit fund to deploy the capital, focused on utility-scale, residential solar and commercial and industrial in order to allow our investors to participate in a diversified portfolio with multiple tax equity partnerships.
There is, to answer your question, flexibility amongst our investor base for different types of structures and different types of projects. This fund will be uniform and default to a partnership flip structure.
PFR: The other structure, primarily, other than the partnership flip, is the sale leaseback. Is that correct?
Cheng, RBC: There’s a third, which is inverted lease, which would be more attractive to our investors than a sale leaseback structure.
PFR: So, from your point of view, investors are still very much interested in investing through tax equity, notwithstanding the fact that there was a big shock to the economy as a result of the pandemic. Did that depend on the kind of investor, or the individual investor? Did some pull back or others come in to replace them?
Cheng, RBC: Yes, there was a pause at the beginning of the pandemic for some of our investors, but they re-engaged pretty quickly, and we ended up having a record year last year.
Overall, there's been a constraint on supply of tax equity this year due to Covid and the uncertainty that that's presented. Our investors, some of them insurance companies or large corporates, were fortunate enough to be in sectors where that tax appetite was not materially affected. So our particular investor base maintained their interest in renewable energy tax equity investments. That's where we have seen our growth this past year and expect it to continue this coming year.
Given the constraint in the overall supply of tax equity in the market, and we're seeing a very high supply of available projects both for 2021 and 2022, we're actively evaluating transactions with that backdrop right now.
PFR: Has that resulted, over the past year, in a dynamic where the terms of tax equity transactions are more favorable to the investor? Or have they stayed the same?
Cheng, RBC: Pricing has definitely increased, I would say probably by 75 bp to 100 bp, over the last year. Sponsor partners are focused on certainty of close, given the supply/demand dynamics in the market.
Overall, I'd say that the constraint on overall tax equity supply has increased the opportunities that we're seeing in the market for our investors, who are typically focused on utility-scale projects with investment grade offtakes. That scrutiny on the offtake, and in some cases the sponsor’s credit, has been more of a focus.
PFR: I understand another possible area for negotiation between sponsors and tax equity investors is how far in advance of the expected commercial operations commitment can be expected. Has there been any movement on that side?
Cheng, RBC: Typically, for utility-scale projects, we will close on commitments anywhere from six to nine months, and in some cases one year ahead of the ultimate placement in service.
For us, the types of deals that we do, which are typically in the $30 million to $100 million bracket, that aligns pretty well with the construction schedule of those types of projects. So, that's been our criteria to date.
To the extent that we deploy into residential and C&I portfolios this year, that might introduce some flexibility, but overall I'd say one year is typically the outside milestone for us.
PFR: In terms of credit profile, within renewable energy, residential solar in particular is a bit of an outlier, because it's more of a consumer-type credit risk. How do you cope with that in a fund that might invest in both?
Cheng, RBC: We have experience investing in residential as well as C&I projects, so we understand that risk and it just becomes an underwriting exercise, in terms of the offtake credit, residential mix, as well as also the structure of our tax equity investment.
Tax equity is usually senior in the waterfall regardless of the asset type. It takes a minority of the cash flow distributions. And so, besides the credit offtake underwriting, this becomes oftentimes a downside case analysis with a coverage ratio lens. We have our usual underwriting and diligence process for each asset class, and essentially we look at projects on an individual basis.
PFR: Are tax equity investors generally comfortable with the range of offtake structures that are being deployed by developers, like hedges, virtual PPAs and new things we're hearing about called proxy generation PPAs?
Cheng, RBC: Yes, we finance deals that have virtual PPA structures and fixed-floating swaps, financially settled hedges. We're looking at proxy gen PPAs, etc. We have also financed projects that have merchant exposure to a certain extent.
Again, for us, it's become a question of underwriting in terms of the project-level cash flows, looking at downside cases that are reasonable, and then layering on the assumptions that we have for the structure and what that structure does to mitigate those downside cases and overall coverage, with the backdrop of the offtake credit being important.
PFR: The tax equity market, of course, is uniquely linked to federal tax policy in the US. How does the recent change in the political landscape in DC affect the outlook for the availability of tax equity for renewable energy projects?
Cheng, RBC: On the project supply side, the extension of the ITC phase-out schedule will create additional supply of opportunities and projects that need tax equity financing. That bodes well for the opportunities that we see in the future.
In terms of the tax appetite, as it relates to speculation that the corporate tax rate could be raised in the future, theoretically that should increase overall tax appetite and supply of tax equity in the market.
Right now, given the lack of visibility into when that could be, we haven't seen it really have an impact on the supply yet to date.
PFR: And finally, with recent guidance on tax incentives for carbon sequestration and storage, is that something that RBC is looking at and do you have any idea when we can expect to see a deal for that kind of project?
Cheng, RBC: Yes, we've looked into 45Q credit opportunities as well as having an eye on standalone storage as it relates to the ITC, and are waiting for guidance there, for certainty on both of those fronts. While we're tracking it, it's not something that we've dug into very deeply. Right now, the available supply of solar ITC projects allows our investors to continue focusing on that asset class. In the future, we anticipate that standalone storage and carbon sequestration opportunities will become more of a focus, but for now it's mostly solar projects.
PFR: Thanks, Jonathan. And finally, it would be great to get a borrower's perspective. Meghan, you alluded earlier to financings that were lined up and that went ahead pretty much as planned, but were there any longer-term disruptions to the markets? Did you meet all of your expectations last year?
At the project level, looking at construction and development, we really had to make sure that we understood any potential impact as the Covid scenario was unfolding, what could it mean for construction schedule, delivery of equipment, etc.
In order to secure construction financing – which, again, is a significant part of the activity we do – we had to make sure that we really understood how those risks were evolving, to get more comfortable with how it would be mitigated, and there was significant protection within the contracts and within the financing itself.
I would say that we were able to successfully do that. We met all of our goals. We financed over 1.5 GW of new wind and solar projects last year. We got it all done, but there was a lot of work through the process in understanding and making sure we were adequately dealing with any potential impacts from Covid.
In addition to that, we did something which I think is somewhat elusive, which is an investment grade private placement on a wind asset with a merchant tail. That was pre-Covid. It was for an operating asset. We refinanced a couple of other operating wind assets, so we were also able to benefit from the lower interest rate environment and the operating history of those projects.
We also re-priced our thermal term loan B. That was one of the last term loan Bs to be re-priced in February, just pre-crisis, before the market shut down, and now it's since reopened, so some of our timing happened to be good.
We also raised tax equity on several new solar projects. Not without its challenges but we were able to get everything done.
PFR: As you've tracked the various markets through the pandemic and the ensuing disruption, has your outlook on the various financing markets that are available for project finance changed as a result or are you looking broadly at the same toolkit that you were before?
Schultz, Invenergy: The market that you go to to finance something is very much based on the cash flow profile of the project itself, when we're talking about project finance or even corporate deals. So, which market is best suited for which asset, whether you're in the construction phase, operating phase, merchant, contracted – those dynamics will remain the same.
Right now, the commercial bank market is flush with liquidity, as Brian was alluding to. We think prices look attractive and there are quite a few lenders active in the space, both banks that have been doing this for a long time and more new entrants to the space as well.
The term loan B market, as always, is the most volatile, and was the one market that shut down for a number of months. Right now it looks amazing, but there were a number of months last year where there was no activity. I think that's one of the reasons why the term loan B market, many times, is not used to finance a construction asset. There are multiple reasons, but it's really much more suited for an operating asset, when you can really pick the best time to go to market, when the market is attractive, and when you have de-risked from a construction perspective. There are probably certain unique situations where that market makes sense for Invenergy.
And then with private placements, similarly, it depends on the profile of the asset itself. Certainly, for the right asset, there can be opportunities there.
Coming back to the tax equity market, we definitely see that there are constraints there. When you look at the statistics, even for last year, there was $18 billion or $19 billion of tax equity that was placed, 50% of which was provided by the two largest institutions in the space. If you add the next two biggest institutions, you get to 75% of the space. So 75% of the investments were done by four investors, which just makes it really clear what an outsize impact those investors have in the renewable space, and their ability to decide which deals they want to do, to dictate terms. For a company like Invenergy, we have the track record to differentiate ourselves, but there are other sponsors that may struggle to secure tax equity.
That's one of the reasons why we are a strong advocate for direct pay and the refundability of tax credits in order to help ensure that all these projects that are contracted – now that we've got this extension for the ITC and PTC – that these projects can get built.
PFR: There are a couple of other markets that we haven't talked about in much detail, one of which is financing for pre-construction or earlier development-stage projects. That includes loans that are used for safe harboring purposes. Some banks provide those loans but there are also non-bank lenders that provide financing for early-stage development projects. To the extent that Invenergy looks at those kinds of financing tools, how has that evolved in the past year or two?
Schultz, Invenergy: On the safe harbor side, there are a couple of different constructs that are out there that were used for wind in 2016, and then every year since, as sponsors have looked to finance more equipment, to safe harbor that. In addition to the financing we did, there were maybe two other wind safe harbor deals that were done, and those were really used as a template for the solar deals that were done in 2019.
Since then, I haven't heard of much new activity on the safe harbor side. If you're doing it on the wind side, you have established what you're doing and can just tack onto it every year in the same structure.
With solar, before the last tax credit extension, people safe-harbored a significant amount of equipment in 2019. And the step down from 30% to 26% maybe didn't provide a strong enough incentive for people to safe harbor as much equipment last year as they did the prior year.
The other point I'd like to make on safe harboring is that acquiring equipment is only one way of satisfying the construction test of onsite work and offsite physical work, and investors have gotten more comfortable with those different forms of starting construction.
There's also, maybe, less of a need to buy significant amounts of equipment, because there are much lower carrying costs to start work onsite or offsite. That has probably also driven some of the reduction in the need to finance safe-harbored equipment.
PFR: We’ve begun to hear more about financing for PPA deposits and interconnection deposits.
Schultz, Invenergy: For Invenergy I would think of that more as a corporate facility, like a working capital, revolver, letter of credit facility, which we don't disclose details of. I think it's very specific to the sponsor, what their credit profile looks like and what their overall capital structure looks, like in terms of their equity ownership, their liquidity. There are various ways of financing preconstruction but it very much depends on the profile of the sponsor.
PFR: Finally, do you think the election outcome – not just the presidential election of course but also the Senate runoffs in Georgia – will have an impact on where Invenergy looks to invest in the US going forward?
Schultz, Invenergy: No, I think we've already been very bullish on renewables. We continue to be, as well as the need to build out transmission to support the growth of renewables and the integration of storage. If anything, it just accelerates the growth in the space and overall it's a very positive trend for the industry. I don't think it changes what we're doing other than maybe continuing to expand and accelerate in those areas.